1. Field of the Invention
The invention relates generally to downhole motors and pumps for oil and gas wells. More particularly, invention relates in general to bearing assemblies for downhole motors and pumps used to drill wells and recover oil and gas from wells.
2. Background of the Technology
In drilling a borehole (or wellbore) into the earth, such as for the recovery of hydrocarbons or minerals from a subsurface formation, it is conventional practice to connect a drill bit onto the lower end of a “drill string”, then rotate the drill string so that the drill bit progresses downward into the earth to create the desired borehole. A typical drill string is made up from an assembly of drill pipe sections connected end-to-end, plus a “bottom hole assembly”(BHA) disposed between the bottom of the drill pipe sections and the drill bit. The BHA is typically made up of sub-components such as drill collars, stabilizers, reamers and/or other drilling tools and accessories, selected to suit the particular requirements of the well being drilled. Often a drilling jar is employed in the BHA to aid in freeing a drill string that has become stuck in the hole. The drilling jar is usually positioned above the uppermost stabilizer in a BHA.
In borehole drilling operations, the drill string and bit are rotated by means of either a “rotary table” or a “top drive” associated with a drilling rig erected at the ground surface over the borehole (or in offshore drilling operations, on a seabed-supported drilling platform or suitably-adapted floating vessel). During the drilling process, a drilling fluid (commonly referred to as “drilling mud” or simply “mud”) is pumped under pressure downward from the surface through the drill string, out the drill bit into the wellbore, and then upward back to the surface through the annular space (“wellbore annulus”) between the drill string and the wellbore. The drilling fluid carries borehole cuttings to the surface, cools the drill bit, and forms a protective cake on the borehole wall (to stabilize and seal the borehole wall), as well as other beneficial functions. At surface the drilling fluid is treated, by removing borehole cuttings, amongst other possible treatments, then re-circulated by pumping it downhole under pressure through the drill string.
As an alternative to rotation by a rotary table or top drive alone, a drill bit can also be rotated using a “downhole motor” incorporated into the drill string immediately above the drill bit. The technique of drilling by rotating the drill bit with a downhole motor without rotating the drill string is commonly referred to as “slide” drilling. It is common in certain types of well-drilling operations to use both slide drilling and drill string rotation, at different stages of the operation. The increased use of downhole motors is mostly attributable to their employment in the drilling of wellbores directionally, and such motors are generally considered to enhance the control and productivity of drilling of such wellbores.
A typical downhole motor includes a top sub, a hydraulic drive section, a drive shaft, a bearing assembly, and a bottom sub. The top sub connects the motor to the drill string and the bottom sub connects the motor to a drill bit. In general, the term “sub” refers to any small or secondary drill string segment or component. The hydraulic drive section, also known as a power section or rotor-stator assembly, includes a helical rotor rotatably disposed within a stator. The drive shaft is enclosed within a drive shaft housing and has an upper end connected to the rotor of the power section. The bearing assembly includes a mandrel with an upper end coupled to the lower end of the drive shaft and a lower end adapted to receive the drill bit. In general, the bearing assembly functions to protect the motor from off bottom and on bottom axial forces while simultaneously permitting rotation of the rotor and driveshaft.
The downhole motor, which may also be referred to as a mud motor or progressive displacement motor (PDM), converts hydraulic energy of a fluid such as drilling mud into mechanical energy in the form of rotational speed and torque output, which may be harnessed for a variety of applications such as downhole drilling. In particular, the high pressure drilling fluid or mud is pumped under pressure between the rotor and stator, causing the rotor, as well as the drill bit coupled to the rotor, to rotate relative to the stator. In general, the rotor has a rotational speed proportional to the volumetric flow rate of pressurized fluid passing through the hydraulic drive section.
Bearing assemblies for mud motors are typically one of two types—either a mud-lubricated bearing assembly or a sealed oil-bath bearing assembly. Unsealed, mud lubricated bearing assemblies are often employed in order to eliminate the difficulties associated with successfully implementing a rotary seal which is capable of withstanding the unusually hostile conditions of the downhole drilling environment. In unsealed bearing assemblies, the radial loads from the bit are carried by elastomer marine bearings, and the axial loads are carried by a ball or roller thrust bearings, often made from tungsten carbide to enhance abrasion resistance. The radial and the thrust bearings are cooled and lubricated by the diversion of a small amount of the circulating drilling fluid. In general, unsealed bearing sub-assemblies have a limited operating life as compared to sealed oil-bath system due to accelerated bearing wear. This limitation undesirably increases drilling costs by requiring frequent trips out of the hole for motor replacement.
Sealed bearing assemblies are filled with bearing lubricant which is pressure balanced to the drilling fluid pressure in the drill string bore. The lubricant is retained within the housing and isolated from the drilling fluid by means of rotary sealing elements at each end of the housing. As the drilling fluid passes through the drill bit jets and enters the annulus of the well, its pressure typically drops 500 to 1,500 psi below the drill string bore pressure. Consequently, the seal arrangement of most conventional sealed bearing assemblies must withstand a 500 to 1,500 psi pressure drop between the bearing lubricant and the drilling fluid in the well annulus.
The durability of a downhole motor and sealed bearing assembly depend, at least in part, on the function of the bearing assembly seals. Bearing failure in normal operation of a sealed oil-bath bearing assembly of a downhole motor is usually a result of a seal failure, which permits drilling fluid incursion into the space occupied by the bearings. Drilling fluid incursion into the bearing assembly oil reservoir will increase the likelihood of failure during operations and increase the cost of maintenance or repair.
Among other important attributes of a bearing assembly utilized in a downhole motor is its overall length. In general, a shorter length downhole motor bearing assembly will reduce the dimension from the drill bit to the bend in the housing, permitting higher angle build rates in a wellbore when drilling directionally, and reduced stress on the components directly above and below the housing when rotating the downhole motor in the wellbore. Some conventional bearing assembly seal systems employ a lower dynamic seal located in a hydraulic force-balanced piston below the radial and thrust bearings, and an upper dynamic seal located in a hydraulic force-balanced piston above the radial and thrust bearings. However, inclusion of lower force-balanced piston generally increases the distance from the drill bit shoulder on the mandrel to the lower end of the lower radial bearing within the housing and increases the distance between the lower dynamic seal and the lower end of the lower radial bearing. Moreover, deflection and/or run-out between the driveshaft housing and the mandrel is detrimental to the life of dynamic seals. The inclusion of a lower dynamic seal disposed in a moveable, lower force-balance piston increases the distance between the lower end of the radial bearing and the lower dynamic seal, which can exasperate such deflection and/or run-out.
Accordingly, there remains a need for improved sealing arrangements for downhole motor bearing assemblies. Such sealing arrangements would be particularly well-received if they offered the potential to enhance the durability of the downhole motor, reduce the length of the downhole motor, and reduce the distance between the bearings and the lower dynamic seal.